Present enhanced kick detection systems in use have been based on advanced flow measurements such as Coriolis meter and to keep control over total active volume and rate of penetration (ROP). However, to create a kick detection system that rely on changes in volume flow has shown to be difficult since the expansion of the gas, and hence rapid change in volume flow or gain, typically occurs 800 to 1000 meter below sea surface and in large water depths, as this will be too late since the gas has then already passed the subsea BOP.
Hydrates may also form if the pressure is high and temperature low enough, making early kick detection based on volume control almost impossible. This is due to the fact that when hydrates have been formed, the gas or hydrates will not expand until the hydrates “melt”. The gas molecules are “trapped and/or hidden” within a crystal structure of water molecules, and will be transported like a “trojan horse”, up the wellbore and high up the drilling riser. When the pressure is low enough, and the hydrates have been transported high up in the riser, the gas will be released and will expand rapidly, see details in FIG. 1.
Severe circulation losses are often encountered when drilling naturally fractured formations, particularly carbonate (limestone, dolomite, etc.). Lost circulation and losses are also encountered when drilling in highly depleted reservoirs where the fraction pressure in the pay zone may be lower than the pore pressure in the overlying layers. The same phenomenon is also encountered when drilling in some special areas such as the “Pre-salt” layers outside Brazil, in particular in the gouge zones below the salt and other naturally fractured and unconsolidated formations. In conjunction with drilling in these types of formations, a special type of Managed Pressure Drilling (MPD) called “Mud Cap Drilling” is used to overcome the challenge with a sudden drop in pore and fraction pressure. A sacrificial fluid (often water) is pumped through the drill string and lost to the formation while the annulus is filled from the top, typically with a light mud (LAM, Light Annular Mud). In these situations, gas kick from a high pressure overlying layer, can happen simultaneously with lost circulation in the low pressure zone. Hydrocarbon influx may also be caused by swap out (no gain or loss observed) as light hydrocarbons are displaced with the more heavier drilling fluid. Kick detection based on volume control (gain/loss) is therefore a challenge. To avoid that the gas migrates up the annulus, LAM will be pumped down the annulus at a greater speed then the gas migration velocity to “bullhead” any potential gas back into a lower pressure zone. As any potential gas influx are bullheaded down and mix with the relative cold sacrificial fluid (water), hydrates may form, making kick detection based on traditional method such as volume control and “flow check” impossible. When hydrates form, the displaced volume of the influx is reduced by approximately 50%. This means that gas influx behavior when the well is shut-in will be observed different from what is expected. When dense gas and water form, the total volume is reduced and the density increases. Hence the observed loss of drilling fluid may be an indication of hydrocarbon influx. This phenomenon can also be observed as slight reductions of shut-in pressure over the time period were hydrates are forming. If hydrates have already formed, it is difficult to detect because the hydrates will have almost the same density as the water it has replaced, and the well can incorrectly be interpreted as “dead”, because the well may not flow or shut-in pressure will not increase.
Other early gas detection systems have also been tried out based on Measurement While Drilling (MWD) based on different physical properties between mud and influx. In one such system the measurements are based on the fact that a pressure pulse (or sound waves) have a different speed depending on whether the pulse travels through mud, water, oil or gas and this can be registered in a sudden change or variation in phase and/or amplitude of the pressure wave (pulse). However, since the gas is in dense phase at the time of influx, it will form an almost perfect homogeneous fluid and mix easily with the mud. Especially with oil based mud, because some of the base oils in use have similar physical properties as the influx in dense phase.
Other early kick detection systems have been based on the different physical properties between mud (mud base fluid) and influx. Documents U.S. Pat. No. 4,733,233 A and EP 2.417.432 A1 are examples of this. The challenge in these solutions is that the influx tends to form a homogeneous mixture with the mud base fluids. Additionally, under high pressure, the density difference etc. between the influx and the base fluids are not so large (especially with oil based mud), and the difference is therefore hard to detect. An analogue to this is that it is hard to detect your CO2 “bubbles” in a bottle of champagne before you release the pressure by opening the bottle.
WO 2013/055706 A1 focus on the change in density or pressure and states that if the annular pressure gradient decreases, then you have a wellbore influx (compare FIG. 5 in said publication). However, this is not always true due to the fact that as the influx travels up the annulus the gas expansion (and hence change in density) is very small under the high pressure typically present deep down in the well. As the influx is further cooled down when it reaches the colder annulus fluid in the wellhead and riser (especially in deep water), the gas may react with water and form hydrates resulting in that the measured pressure and density will increase rather than decrease, see FIG. 1. Additionally, a decrease in density may result from a number of other reasons, such as a reduction in cuttings content in the annulus due to low or now rate of penetration (ROP), giving a “false alarm” even if influx is not actually present.
In US 2013/0090855 A1 a method for computing a density of an inflow constituent is claimed. The method evaluates the density of the inflow constituent computed to identify the inflow constituent (i.e., gaseous, oil or water). However the disclosure does not consider the risk of hydrates forming in the wellbore. Such hydrates formed in the wellbore are difficult to detect because the hydrates will have almost the same density as the water it has replaced, and the density of the inflow constituent computed may have almost the same density as wellbore annulus constituent prior to the influx.